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A METHOD AND A SYSTEM FOR ABATING H2S AND CO2 FROM H2S AND CO2 RICH GAS MIXTURES SUCH AS GEOTHERMAL NON-CONDENSABLE GAS MIXTURES

20220339576 · 2022-10-27

    Inventors

    Cpc classification

    International classification

    Abstract

    This invention relates to a method and a system for abating hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from H.sub.2S and CO.sub.2rich gas mixtures such as geothermal non-condensable gas mixtures (NCG). The H.sub.2S and CO.sub.2 gas is separated from the remaining gases contained in the H.sub.2S and CO.sub.2rich gas mixtures by pressurizing the gas stream and feeding it into an absorption column where H.sub.2S and CO.sub.2 are preferentially dissolved in a water stream, resulting in water stream rich in H.sub.2S and CO.sub.2. The H.sub.2S and CO.sub.2 rich water stream may then be re-injected into a geological reservoir or used for pH modification of another water stream of geological origin.

    Claims

    1. A method for abating hydrogen sulfide (H.sub.25) and carbon dioxide (CO.sub.2) from a Non-Condensable gas (NCG) mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, comprising the steps of: pressurizing said NCG mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, to a pressure between 3 and 20 bar, and contacting a stream of said pressurized NCG mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2), absorption of at least part of said H.sub.25 and CO.sub.2 from said pressurized NCG mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby separating said at least part of said H.sub.25 and CO.sub.2 from at least part of said at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar and producing a stream of water (W4) enriched with dissolved H.sub.25 and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.25 and CO.sub.2 compared to said NCG mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, transferring said water stream (W4) enriched with dissolved H.sub.25 and CO.sub.2: either to an injection well for injecting said water stream (W4) into a geological reservoir, or to a system for injection of a water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid for pH-regulation of said water stream (W5).

    2. A method according to claim 1, wherein the pressure of said pressurized NCG mixture (G1), encompassing H.sub.25 and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is between 3 and 20 bar, or between 4 and 10 bar, or between 6 and 8 bar, or 7 bar.

    3. A method according to claim 1, wherein the temperature of said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is between 30 and 60° C., or between 35 and 50° C., or between 39 and 41° C., or 40° C.

    4. A method according to claim 1, wherein the temperature of said water stream (W2) is between 4 and 40° C., or between 6 and 35° C., or 8 and 30° C., or between 10 and 25° C., or between 12 and 20° C., or between 13 and 17° C., or 15° C.

    5. A method according to claim 1, wherein the flow of said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is between 0.2 and 1.5 kg/s, or between 0.25 and 1.45 kg/s, or between 0.4 and 1.4 kg/s, or 1 kg/s.

    6. A method according to claim 1, wherein the flow of said water stream (W2) is between 36 and 56 kg/s, or between 45 and 55 kg/s, or between 48 and 52 kg/s, or 50 kg/s.

    7. A method according to claim 1, wherein said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is a geothermal non-condensable gas mixture.

    8. A system for abating hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a Non-Condensable Gas (NCG) mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, comprising at least the following: means for pressurizing said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, to a pressure between 3 and 20 bar, and means for contacting a stream of said pressurized NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2), means for absorption of at least part of said H.sub.2S and CO.sub.2 from said pressurized NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby separating said at least part of said H.sub.2S and CO.sub.2 from at least part of said at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar and producing a stream of water (W4) enriched with dissolved H.sub.2S and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.2S and CO.sub.2 compared to said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, means for transferring said water stream (W4) enriched with dissolved H.sub.2S and CO.sub.2: either to an injection well for injecting said water stream (W4) into a geological reservoir, or to a system for injection of a water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid for pH-regulation of said water stream (W5).

    9. A system according to claim 8 wherein said means for contacting a stream of said pressurized NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2), and means for absorption of at least part of said H.sub.2S and CO.sub.2 from said pressurized NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby separating said at least part of said H.sub.2S and CO.sub.2 from at least part of said at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar and producing a stream of water (W4) enriched with dissolved H.sub.2S and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.2S and CO.sub.2 compared to said NCG mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, are an absorption column.

    Description

    BRIEF DESCRIPTION OF THE DRAWINGS

    [0050] Hereinafter a number of embodiments of the invention are described, by way of example only, with reference to the drawings, in which

    [0051] FIG. 1 shows the amount of CO.sub.2 and H.sub.2S emitted by various Icelandic geothermal power plants.

    [0052] FIG. 2 shows a flowchart of a method according to the present invention of separating soluble gases including hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a H.sub.2S and CO.sub.2rich gas mixture containing at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar gases, such as NCG.

    [0053] FIG. 3 shows a system according to the present invention for separating soluble gases including hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a H.sub.2S and CO.sub.2rich gas mixture containing at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar gases, such as NCG.

    [0054] FIG. 4 shows an absorption column and a re-injection well in accordance with a system and a method according to the present invention

    [0055] FIG. 5 shows a method for abating CO.sub.2/H.sub.2S in accordance with the present invention (in an absorption column at 5-6 bar) followed by use either for (1a) re-injection as an aid in pH modification, or for (1b) re-injection into a geological reservoir.

    DESCRIPTION OF EMBODIMENTS

    [0056] FIG. 2 shows a flowchart of a method according to the present invention of separating soluble gases including hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a H.sub.2S and CO.sub.2rich gas mixture containing at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar gases, such as geothermal non-condensable gas (NCG). It should be noted that the H.sub.2S and CO.sub.2rich gas mixture should not be construed as being limited to NCG. However, for simplicity, in the following it will be assumed that the H.sub.2S and CO.sub.2rich gas mixture is NCG, where the NCG may further contain, but is not limited to, one or more gases selected from H.sub.2, N.sub.2, Ar and CH.sub.4.

    [0057] In step (S1) 201, the H.sub.2S and CO.sub.2 gas is separated from the remaining gases contained in the NCG. As will be discussed in more details in relation to FIG. 3, this is preferably performed by conducting the NCG through an absorption column where the H.sub.2S and CO.sub.2 becomes dissolved in a liquid, typically water, and in that way separated from the remaining more poorly-soluble H.sub.2 , N.sub.2, CH.sub.4 and Ar gases. Subsequently, the resulting water stream comprising dissolved H.sub.2S and CO.sub.2 is conducted to e.g. re-injection well for disposal/storage or into another process for pH modification.

    [0058] Referring to FIG. 3 the present invention in particular relates to a method for abating hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, comprising the steps of:

    [0059] pressurizing said gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, and

    [0060] contacting a stream of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2),

    [0061] absorption of at least part of said H.sub.2S and CO.sub.2 from said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby

    [0062] producing a stream of water (W4) enriched with dissolved H.sub.2S and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.2S and CO.sub.2 compared to said gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar,

    [0063] transferring said water stream (W4) enriched with dissolved H.sub.2S and CO.sub.2: [0064] either to an injection well for injecting said water stream (W4) into a geological reservoir, or [0065] to a system for injection of a water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid for pH-regulation of said water stream (W5)

    [0066] The steps of transferring said water stream (W4) enriched with dissolved H.sub.2S and CO.sub.2 either to an injection well for injecting said water stream (W4) into a geological reservoir, or to a system for injection of a water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid for pH-regulation of said water stream (W5) are not shown in FIG. 3.

    [0067] The step of transferring said water stream (W4) enriched with dissolved H.sub.2S and CO.sub.2 to an injection well for injecting said water stream (W4) into a geological reservoir is shown in FIG. 4. In the particular embodiment shown in FIG. 4, the water stream (W4) is co-injected with another water stream labelled “Geothermal water”.

    [0068] The use of water stream (W4) for pH-modification of water stream (W5) is not shown in FIG. 3 or 4, but is shown in e.g. FIG. 5, where part of water stream (W4) is used for re-injection (1b) and part is used for pH-modification (1a) of the water stream (W5), which is marked as “Geothermal water”.

    [0069] In a particularly preferred embodiment of a method according to the present invention the pressure of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is between 3 and 20 bar, such as between 3 and 15 bar, or between 4 and 20 bar, such as between 4 and 14 bar, such as between 5 and 13 bar, such as 6 and 12 bar, such as 7 and 11 bar, e.g. 7, 8, 9, 10 and 11 bar.

    [0070] In a further particularly preferred embodiment of a method according to the present invention the temperature of said gas stream (G1) is between 30 and 50° C., such as between 32 and 48° C., such as between 33 and 47° C., such as between 34 and 46, such as between 35 and 45, such as between 36 and 44, such as between 37 and 43, such as between 38 and 42 such as 39, 40 and 41° C.

    [0071] In a further particularly preferred embodiment of a method according to the present invention the temperature of said water stream (W2) is between 4 and 40° C., such as between 6 and 35° C., such as between 8 and 30° C., such as between 10 and 25° C., such as between 11 and 24° C., such as between 12 and 23° C., such as between 13 and 22° C., such as between 14 and 21° C., such as between 15 and 20° C., such as 15, 16, 17, 18, 19 and 20° C.

    [0072] In a further particularly preferred embodiment of a method according to the present invention the pressure of said water stream (W2) is between 6 and 23 bar, such as between 6 and 22 bar, such as between 6 and 21 bar, such as between 6 and 20 bar, such as between 6 and 19 bar, such as between 6 and 18 bar, such as between 7 and 17 bar, such as between 8 and 16 bar, such as 9 and 15 bar, such as 10 and 14 bar, e.g. 9, 10, 11, 12, 13 and 14 bar. In a particularly preferred embodiment of a method according to the present invention the pressure of said water stream (W2) is app. 2 to 5 bar above the pressure of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, such as 3 or 4 bar above the pressure of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar. Thus, if the pressure of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, is app. 6 bar the pressure of said water stream (W2) should preferably be app. 9 bar. Nonetheless, A skilled person will recognize that the optimal pressure difference between the pressures of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, and said water stream (W2) will depend on e.g. the column height of the applicable absorption column and the pressure drop in the applicable water distribution system, just like it will depend on where in a given system said pressures are measured.

    [0073] In a further particularly preferred embodiment of a method according to the present invention the flow of said gas mixture (G1) is between 0.2 and 1.5 kg/s, such as between, kg/s 0.25 and 1.45 kg/s, such as between 0.3 and 1.4 kg/s, such as between 0.35 and 1.35 kg/s, such as between 0.4 and 1.3, such as between 0.45 and 1.25 kg/s, such as between 0.5 and 1.2 kg/s, such as between 0.55 and 1.15 kg/s, such as between 0.6 and 1.1 kg/s, such as between 0.65 and 1.05 kg/s, such as between 0.7 and 1 kg/s, such as 0.7, 0.75, 0.8, 0.85, 0.9, 0.95 and 1 kg/s.

    [0074] In a further particularly preferred embodiment of a method according to the present invention the flow of said water stream (W2) is between 36 and 56 kg/s, such as between 37 and 55 kg/s, such as between 38 and 54 kg/s, such as between 39 and 55 kg/s, such as between 40 and 53 kg/s, such as between 41 and 52 kg/s, such as between 42 and 51 kg/s such as 42, 43, 44, 45, 46, 47, 48, 49 and 50 kg/s.

    [0075] In a further particularly preferred embodiment of a method according to the present invention said gas mixture (G1) is a geothermal non-condensable gas mixtures (NCG).

    [0076] Also, apart from the above-mentioned methods the present invention also in particular relates to a system for abating hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from a gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, comprising the at least the following: [0077] means for pressurizing said gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, and [0078] means for contacting a stream of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2), [0079] means for absorption of at least part of said H.sub.2S and CO.sub.2 from said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby producing a stream of water (W4) enriched with dissolved H.sub.2S and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.2S and CO.sub.2 compared to said gas mixture (G1) encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, [0080] means for transferring said water stream (W4) enriched with dissolved H.sub.2S and CO.sub.2: [0081] either to an injection well for injecting said water stream (W4) into a geological reservoir, or [0082] to a system for injection of a water stream (W5) into a geological reservoir for use of said water stream (W4) as an aid for pH-regulation of said water stream (W5)

    [0083] In a particular preferred system according to the present invention said [0084] means for contacting a stream of said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, with a stream of water (W2), and [0085] means for absorption of at least part of said H.sub.2S and CO.sub.2 from said pressurized gas mixture (G1), encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, into said water stream (W2), thereby producing a stream of water (W4) enriched with dissolved H.sub.2S and CO.sub.2 comparable to said water stream (W2) and a stream of pressurized gas (G3), which has been depleted of H.sub.2S and CO.sub.2 compared to said gas mixture (G1), [0086] encompassing H.sub.2S and CO.sub.2 and at least also one of H.sub.2, N.sub.2, CH.sub.4 and/or Ar, are an absorption column.

    [0087] While the invention has been illustrated and described in detail in the drawings and foregoing description, such illustration and description are to be considered illustrative or exemplary and not restrictive; the invention is not limited to the disclosed embodiments. Other variations to the disclosed embodiments can be understood and effected by those skilled in the art in practicing the claimed invention, from a study of the drawings, the disclosure, and the appended claims. In the claims, the word “comprising” does not exclude other elements or steps, and the indefinite article “a” or “an” does not exclude a plurality. A single processor or other unit may fulfill the functions of several items recited in the claims. The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measured cannot be used to advantage. Any reference signs in the claims should not be construed as limiting the scope.

    EXAMPLES

    Example 1

    [0088] Experimental injection of CO.sub.2/H.sub.2S was carried out at Hellisheiði Power plant located on the Hengill central volcano, which is located in the western volcanic zone SW-Iceland, approximately 20 km southeast of Reykjavik. Currently the Hengill area has two producing geothermal fields, Nesjavellir in the northern part and Hellisheiði in the southern part of the area.

    [0089] 63 production wells have been drilled into the Hellisheiði geothermal field providing valuable information about its stratigraphy and alteration zones. The sub-surface basaltic strata in the Hengill area comprise mostly hyaloclastite volcanic formations down to some 1000 m below sea level depth and underlain by a more dominant lava succession as reported in the scientific literature by Franzson et al., Franzson, H., Kristjánsson, B. R., Gunnarsson, G., Bjornsson, G., Hjartarson, A., Steingrímsson, B., Gunnlaugsson, E. and Gíslason, G. (2005) The Hengill-Hellisheiði Geothermal field. Development of a Conceptual Model. Proceedings World Geothermal Congress 2005, hereby incorporated in it's entirety by reference. Hydrothermal alteration ranges from fresh rocks in the overlying cold groundwater system through zeolite assemblage and into high-temperature mineral assemblage including epidote, wollastonite and actinolite as reported in the scientific literature by Helgadóttir et al., Helgadóttir, H. M., Snæbjörnsdóttir, S. O., Níelsson, S., Gunnarsdóttir, S. H., Matthíasdóttir, T., Hardarson, B. S., Gunnlaugur M. Einarsson, G. M. and Franzson, H. (2010) Geology and Hydrothermal Alteration in the Reservoir of the Hellisheidi High Temperature System, SW-Iceland. Proceedings, World Geothermal Congress 2010, hereby incorporated in it's entirety by reference.

    [0090] Geothermal gas from Hellisheiði geothermal field consists primarily of CO.sub.2, H.sub.2S, H.sub.2 and to a lesser degree of N.sub.2, CH.sub.4 and Ar. A pilot gas separation station was built next to Hellisheiði power plant. The pilot station separated the geothermal gas coming from the condensers of the power plant into a CO.sub.2 and H.sub.2S rich gas stream (or streams) and a gas stream comprising the other gases (primarily H.sub.2, N.sub.2, Ar, O.sub.2 and/or CH.sub.4). The oxygen in the gas stream separated from the CO.sub.2 and H.sub.2S comes from atmospheric contamination of the geothermal gas. Approximately 3% of the total geothermal gas coming from the power station was separated in this way. The CO.sub.2/H.sub.2S gas stream(s) was used for the CO.sub.2/H.sub.2S injection, whereas the remaining gases where released into the atmosphere along with rest of the geothermal gases coming from the condensers of Hellisheiði power plant.

    [0091] The CO.sub.2/H.sub.2S gas stream(s) was (were) dissolved in groundwater together with potassium iodide tracer close to the injection site and subsequently injected back into the geothermal reservoir. The aim of the project was to use the same governing parameter that are controlling concentrations of e.g. H.sub.2S in the geothermal reservoir to remove H.sub.2S from solution and store it in minerals in the geothermal reservoir.

    [0092] The site chosen for the experimental injection of hydrogen sulfide and carbon dioxide is in Sleggjubeinsdalur approximately 2 km northeast of Hellisheiði Power Plant. It was chosen on the basis of favorable reservoir temperature, proximity to the power plant and therefore the source of H.sub.2S, tracer tests and the fact that on the site high temperature liquid enthalpy wells were available for injection experiments. H.sub.2S gas was transported from a pilot gas separation station, dissolved in geothermal water near the injection site and subsequently injected in well HE-08.

    [0093] HE-08 is a vertical well 2808 m deep drilled in 2003 for production but turned out to be unusable as a production well. This well was selected for injection because during drilling of nearby wells a clear connection between the wells and HE-08 was observed. The connection between the wells was further studied in a tracer test described below.

    [0094] The stratigraphy and alteration of Hellisheiði geothermal field and the injection site has been reported in the scientific literature by Franzon et al., Franzson, H., Kristjánsson, B. R., Gunnarsson, G., Bjornsson, G., Hjartarson, A., Steingrímsson, B., Gunnlaugsson, E. and Gíslason, G. (2005) The Hengill-Hellisheiði Geothermal field. Development of a Conceptual Model. Proceedings Worls Geothermal Congress 2005, and in the scientific literature by Helgadóttir et al., Helgadóttir, H. M., Snæbjörnsdóttir, S. O. , Níelsson, S., Gunnarsdóttir, S. H., Matthíasdóttir, T., Hardarson, B. S., Gunnlaugur M. Einarsson, G. M. and Franzson, H. (2010) Geology and Hydrothermal Alteration in the Reservoir of the Hellisheidi High Temperature System, SW-Iceland. Proceedings, World Geothermal Congress 2010, hereby incorporated in its entirety by reference. The main rock formation in the injection site is sub-glacially formed hyoloclastite with occasional lava series. Below around 1400 m below sea level lava series are dominating. Aquifer temperature at the injection site is between 260° and 270° C. as indicated by the application of the quartz geothermometer of the discharged fluid and calculated formation temperature. The dominating aquifer in HE-08 is at 1350 m depth where formation temperature is around 270° C. which is in good agreement with the quartz geothermometer. The rock formation at the injection site go through all typical alteration zones of high temperature areas from fresh rock to epidote-amphibole zone.

    [0095] During drilling of HE-08 a pressure relationship was observed between HE-08 and KhG-1, which is a nearby well used for water level measurements. During drilling of HE-31, HE-46 and HE-52 pressure relationship was also observed between the drilled well and well HE-8 and KhG-1. Tracer test was performed to reveal and quantify possible flow paths of the H.sub.2S rich geothermal brine (geothermal water) to nearby wells and the result used to compose a monitoring program of the possible monitoring wells.

    [0096] The tracer test was performed by dissolving 250 kg Na-benzoate (NaC.sub.6H.sub.5CO.sub.2) in 1000 liters water followed by injection into well HE-8. After injection of the tracer geothermal brine (geothermal water) was pumped in the well at volumetric flow rate of 4 1/s for 56 days. Wells in the vicinity of the injection well were discharging at the time of the test. The wells were HE-5, HE-31, HE-46 and HE-52. Periodically samples were collected either from their weirbox or with the use of Webre separator and analyzed for the benzoate ion using an ion chromatograph. The concentration of benzoate was under the detection limit in all the samples for wells HE-52, HE-5 and HE-31. Elevated levels of benzoate concentration were only evident in well HE-46. Modeling of the tracer test revealed that close to 40% of the injected water discharged into well HE-46 when taking into account the reported 20% breakdown of benzoate in two weeks at 270° C. The rest of the benzoate was not accounted for. The benzoate injected into HE-08 started to appear in HE-46 after only two days revealing a fast flow path between the two wells. According to the quartz geothermometer, the aquifer temperature is 266° C. which is close to the aquifer temperature in HE-08 and all the wells in the vicinity of the injection site.

    [0097] The concentration of hydrogen sulfide in aquifer fluids in Hellisheiði geothermal area has been extensively studied, both as a part of this injection project and as a part of general geochemical monitoring of the well and been reported in the scientific literature by Stefansson et al. and Scott et al., Stefansson, A., Arnorsson, S., Gunnarsson, I., Kaasalainen, H. and Gunnlaugsson, E. (2011). The geochemistry and sequestration of H2S into hydrothermal system at Hellisheidi, Iceland. J. Volcanol. Geoth. Res. 202, 179-188); Scott S., Gunnarsson, I., Stefansson, A. and Gunnlaugsson, E. (2011). Gas Chemistry of the Hellisheiði Geothermal Field, SW-Iceland. Proceedings 36th Stanford Geothermal Workshop, hereby incorporated in its entirety by reference. The calculated H.sub.2S concentration in the high temperature aquifer fluids is in the range of 15-264 ppm. The concentration increases with rising temperature and appears to be controlled by mineral buffer assemblages. The majority of data points are close to equilibrium lines for the pyrite, pyrrhotite, prehnite and epidote or pyrite, pyrrhotite and magnetite mineral buffers. Stefansson et al. concluded that H.sub.2S concentration equilibrate to the prehnite bearing mineral assemblage because Icelandic geothermal areas are usually low in magnetite indicating that it is unstable in Icelandic geothermal systems.

    [0098] The H.sub.2S abatement method of the present invention depends on the rate of the chemical reactions needed to take place for successful H.sub.2S mineralization. The H.sub.2S needs metals to form the secondary minerals to be permanently stored it in the geothermal reservoir. Reaction path modeling indicates that the main factors affecting the capacity of H.sub.2S mineralization are related to the mobility and oxidation state of iron as reported in the scientific literature by Stefánsson et al., Stefansson, A., Arnorsson, S., Gunnarsson, I., Kaasalainen, H. and Gunnlaugsson, E. (2011). The geochemistry and sequestration of H.sub.2S into hydrothermal system at Hellisheidi, Iceland. J. Volcanol. Geoth. Res. 202, 179-188, hereby incorporated in its entirety by reference. Above 250° C. the rate mineralization of pyrite is reduced upon formation of epidote resulting in more basaltic rock needed to be dissolved to mineralize the H.sub.2S. The optimum temperature for H.sub.2S sequestration would then be below the stability zone of epidote or below approximately 230° C. (see Stefansson et al. reference). The rock formation temperature at the injection site is between 260-270° C. The injected geothermal water containing the dissolved H.sub.2S heats up from 100° C. up to above 260° before entering the monitoring well (HE-46) providing a wide temperature interval for mineralizing the H.sub.2S.

    [0099] Tracer testing of the injection site revealed a direct and fast flow path from the injection well and the monitoring well. The distance between main aquifers is around 450 m. This indicates that the main flow path between the wells is through a fracture in the reservoir which is to be expected in fracture dominated geothermal reservoir like Hellisheiði geothermal field. For the experimental injection to be successful the rate of H.sub.2S mineralization may not be too fast as sulfide minerals might fill up the aquifers in the vicinity of the injection well making it unusable for injection. Circumstances like that would call for measures to slow down the mineralization reaction. These measures might be for example lowering the concentration of H.sub.2S in the injected brine (geothermal water) and therefore lowering the supersaturation of the brine (geothermal water) with respect to the depositing sulfide minerals. On the other hand, the rate of H.sub.2S mineralization might be too slow for any mineralization to take place when the brine (geothermal water) flows from the injection well to the monitoring well. A response to that could be to close down the monitoring well for some time but continue with the injection of H.sub.2S. This would increase the retention time in the geothermal reservoir allowing more time for H.sub.2S sequestration.

    Example 2

    [0100] At the Hellisheidi geothermal power plant in Iceland the non-condensable geothermal gases (NCG), mainly consists of three gases: carbon dioxide (CO.sub.2), hydrogen sulphide (H.sub.2S) and hydrogen (H.sub.2). Other gases such as nitrogen (N.sub.2), methane (CH.sub.4) and argon (Ar) are also part of the NCG gases but only in very small fractions (ref.: http://www.thinkgeoenergy.com/treating-non-condensable-gases-ncg-of-geothermal-plants-experience-by-mannvit/).

    [0101] The Non-Condensable gas fraction which arises as a result of the condensation process applied to the steam from the geothermal site was directed to an absorption column, where NCGs (mainly CO.sub.2, H.sub.2S) were dissolved in water under elevated pressure (6-10 bar) at a constant temperature (15° C.-25° C.).

    [0102] The operational conditions for capturing the water-soluble gases including hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2) from the H.sub.2S and CO.sub.2 rich geothermal non-condensable gas mixture (NCG), are outlined below:

    TABLE-US-00001 1 2 3 4 Stream name Geothermal Gas from gas from Water from absorption water with power plant power plant column dissolved gases Operation Temp [° C.] 40 15 15.2 15.5 Pressure [bara] 1 6 6 6 Flow liquid 0 50 0 50.54 [kg/s] Flow gas [kg/s] 0.8 0 0.26 0 Range: Temp [° C.] 39-41 15-20 15.2-20.2 15.5-20.5 Pressure [bara]  0.9-1.05 5-6 5-6 5-6 Flow liquid 0 36-56 0 50.2-55.4 [kg/s] Flow gas [kg/s] 0.4-0.8 0 0.26 0

    [0103] Up to 98% of the hydrogen sulfide and about 50% of the carbon dioxide was dissolved in the water and re-injected deep into the bedrock at the plant site where H.sub.2S and CO.sub.2 mineralize (ref.: http://www.thinkgeoenergy.com/treating-non-condensable-gases-ncg-of-geothermal-plants-experience-by-mannvit/).

    [0104] The skilled person will readily appreciate that the above-mentioned temperatures, flows and pressures are based on the specific conditions of the Hellisheidi geothermal power plant in Iceland, and that given other pre-determined conditions as regards gas flow and temperature these might be different. Similarly, the skilled person will readily appreciate that the relevant water flow should be a certain ratio of the actual gas flow, which should be changed according to the applicable pressures and temperatures.

    Example 3

    [0105] The present set of experiments were also performed at the geothermal plant in Hellisheidi, Iceland.

    [0106] The subsurface rocks at the injection site consist of olivine tholeiitic basalts which are relatively permeable with an estimated 8-10% porosity and characterized by high permeability fractures at depths below 800 m. The temperature at ˜2000 m depth of the target acid gas storage reservoir ranges from 220 to 260° C.

    [0107] The CO.sub.2 and H.sub.2S were dissolved in water and the mixture was released at a depth of 750 m. The CO.sub.2/H.sub.2S/H.sub.20 mixture was carried from the release point via an injection well extending down to 1900-2200m where it was released to the subsurface rocks. This combined fluid then flowed down a hydraulic pressure gradient to monitoring wells located 0,9-1,5 km from the injection well at 1900-2200 m depth.

    [0108] During a 1 year period a total of 4526 tons of CO.sub.2 and 2536 tons of H.sub.2S was injected. The fate of the injected gas mixture was monitored by the regular sampling of three monitoring wells, located 984 m, 1356 m, and 1482 m downstream from the injection well at the depths of a main aquifers, of about 1900-2200 m depth. At these depths, the reservoir fluid is a single-phase aqueous fluid with a temperature of 266 to 277° C., as the hydrostatic pressure is greater than the liquid-vapor saturation pressure of water. As the fluid rises up the monitoring wells, it boils as the pressure decreases. Consequently, steam and water are sampled separately at 5.7 to 9.3 bars at the top of each monitoring well. Samples for the determination of dissolved inorganic carbon (DIC) and hydrogen sulfide (H.sub.2S), as well as CO.sub.2, and H.sub.2S in the vapor phase were collected and analysed as described by Arnórsson et al. (2006) Geofluids 6, 203-216.

    [0109] The fraction of the injected gas mineralization was computed by comparing measured aqueous DIC and dissolved sulfur (DS) concentrations in the sampled monitoring wells to those calculated assuming only mixing and dilution and no reactions occurred in the subsurface.

    [0110] The difference between the calculated and the measured DIC and DS showed that over 50% of the injected CO.sub.2 and 76% of the injected H.sub.2S were mineralized.

    Example 4

    [0111] The present set of experiments were also performed at the geothermal plant in Hellisheidi, Iceland. The system was operated under the conditions described in example 2.

    [0112] During 153 days, water with dissolved CO.sub.2 (4095-6388 mg/l) and H.sub.2S (1933 to 3811) at the flow rate of 0.9-1.4 l/s were used for pH modification geothermal brine (geothermal water) stream at 18-20 l/s. The concentration CO.sub.2 and H.sub.2S of the pH modified brine (geothermal water) was between 254-448 mg/1 and 170-305 mg/1, respectively with a pH between 5.5 to 6.7. The mixture with a temperature of 117° C. was transferred through a heat exchanger and cooled to 60° C. and the pressure drop across the exchanger was monitored and the amount of scaling estimated by weighing the heat exchanger before and after the experiment. No pressure drop was observed across the heat exchanger and measured scaling was 2 μg/l. For comparison, untreated geothermal brine (geothermal water) was transferred through the heat exchanger for 53 at the same flow rate and temperature drop. The experiment could not be extended further since the heat exchanger clogged with measured scaling of 111 μg/l.